1. Field of the Disclosure
Embodiments disclosed herein relate generally to cutting tools in oilfield applications. More particularly, embodiments disclosed herein relate to drill bits having additional blades to achieve and maintain better stability during drilling operations.
2. Background Art
Rotary drill bits with no moving elements are typically referred to as “drag” bits. Drag bits are often used to drill very hard or abrasive formations. Drag bits include those having cutting elements attached to the bit body, such as polycrystalline diamond compact (PDC) bits, and those including abrasive material, such as diamond, impregnated into the surface of the material which forms the bit body. The latter bits are commonly referred to as “impreg” bits.
An example of a prior art drag bit having a plurality of cutters with ultra hard working surfaces is shown in FIG. 1. The drill bit 10 includes a bit body 12 and a plurality of blades 14 extending radially from the bit body 12. The blades 14 are separated by channels or gaps 16 that enable drilling fluid to flow between and both clean and cool the blades 14 and cutters 18. Cutters 18 are held in the blades 14 at predetermined angular orientations and radial locations to present working surfaces 20 with a desired back rake angle against a formation to be drilled. Typically, the working surfaces 20 are generally perpendicular to the axis 19 and side surface 21 of a cylindrical cutter 18. Thus, the working surface 20 and the side surface 21 meet or intersect to form a circumferential cutting edge 22.
Orifices are typically formed in the drill bit body 12 and positioned in the gaps 16. The orifices are commonly adapted to accept nozzles 23. The orifices allow drilling fluid to be discharged through the bit in selected directions and at selected rates of flow between the cutting blades 14 for lubricating and cooling the drill bit 10, the blades 14 and the cutters 18. The drilling fluid also cleans and removes the cuttings as the drill bit rotates and penetrates the geological formation. Without proper flow characteristics, insufficient cooling of the cutters may result in cutter failure during drilling operations. The gaps 16, which may be referred to as “fluid courses,” are positioned to provide additional flow channels for drilling fluid and to provide a passage for formation cuttings to travel past the drill bit 10 toward the surface of a wellbore (not shown).
The drill bit 10 includes a shank 24 and a crown 26. Shank 24 is typically formed of steel or a matrix material and includes a threaded pin 28 for attachment to a drill string. Crown 26 has a cutting face 30 and outer side surface 32. The particular materials used to form drill bit bodies are selected to provide adequate strength and toughness, while providing good resistance to abrasive and erosive wear.
The combined plurality of surfaces 20 of the cutters 18 effectively forms the cutting face of the drill bit 10. Once the crown 26 is formed, the cutters 18 are positioned in the cutter pockets 34 and affixed by any suitable method, such as brazing, adhesive, mechanical means such as interference fit, or the like. The design depicted provides the cutter pockets 34 inclined with respect to the surface of the crown 26. The cutter pockets 34 are inclined such that cutters 18 are oriented with the working face 20 at a desired rake angle in the direction of rotation of the bit 10, so as to enhance cutting. It will be understood that in an alternative construction (not shown), the cutters can each be substantially perpendicular to the surface of the crown, while an ultra hard surface is affixed to a substrate at an angle on a cutter body or a stud so that a desired rake angle is achieved at the working surface.
Polycrystalline diamond cutting elements are frequently used on fixed-head drill bits. One embodiment of polycrystalline diamond includes polycrystalline diamond compact (“PDC”), which comprises man-made diamonds aggregated into relatively large, inter-grown masses of randomly oriented crystals. Polycrystalline diamond is highly desirable, in part due to its relatively high degrees of hardness and wear resistance. Despite these properties, however, polycrystalline diamond will eventually wear down or otherwise fail after continued exposure to the stresses of drilling. Undesirable bit performance such as vibration and whirling while drilling exacerbates wear and tear on the cutting elements.
The use of PDC bits over roller cone bits has grown over the years, largely as a result of greater rates of penetration (ROPs) frequently attainable using a PDC bit. ROP is a major issue in deep wells. Low ROP (for example, 3 to 5 feet per hour) is primarily a result of a high compressive strength of highly overburdened formations encountered at greater depths. Initially, roller cone bits with hardened inserts used for drilling hard formations at shallower depths were applied as wells went deeper. However, at greater depths it is more difficult to recognize when roller cone bit bearings have failed, a situation that can occur with greater frequency when greater weight is applied to the bit in a deep well. This can lead to more frequent failures, lost cones, more frequent trips, higher costs, and lower overall rates of penetration. PDC bits, having no moving parts, provide a solution to some of the problems experienced with roller cone bits.
However, PDC bits are not without their own inherent problems. “Bit whirl” is a problem that may occur when a PDC bit's center of rotation shifts away from its geometric center, producing a non-cylindrical hole. This may result from an unbalanced condition brought on by irregularities in the frictional forces between the rock and the bit, analogous to an unbalanced tire causing vibrations that spread throughout a car at higher speeds. Bit whirl may cause cutters to be accelerated sideways and backwards, causing chipping that may accelerate bit wear, reduce PDC bit life and reduce rate of penetration (ROP). In addition, bit whirl may result in very high downhole lateral acceleration, which causes damage not only to the bit but also other components in the BHA, such as motors, MWD tools and rotary steerable tools. Bit whirl is well documented as a major cause of damage to PDC drill bits, resulting in short runs, low ROP, high cost per foot, poor hole quality and downhole tool damage. Hence, consistent lateral stability may be highly desirable in PDC bits.
PDC bits may also be more susceptible to this phenomenon as well as to “stick slip” problems, where the bit hangs up momentarily, allowing its rotation to briefly stop, and then slips free at a high speed. While PDC cutters are very good at shearing rock, they may be susceptible to damage from the sharp impacts that these problems can lead to in hard rocks, resulting in reduced bit life and lower overall rates of penetration.
Many approaches have been devised to improve drill bit dynamic characteristics to reduce the detrimental effects to the drill bit. In particular, stabilizing features known as “wear knuckles”, sometimes interchangeably referred to as “contact pads” or “wear knots”, are used to stabilize the drill bit by controlling lateral movement of the bit, lateral vibration, and depth of cut. These stabilizing features project from the bit face, either trailing or leading a corresponding cutting element with respect to a rotational direction about a bit axis.
One characteristic of fixed-head bits having conventional stabilizing features is that the cutting elements extend outwardly of the stabilizing features, to contact the formation in advance of the stabilizing features. The stabilizing features are designed not to contact the formation until the bit advances at a selected minimum rate or depth of cut (“DOC”). In many cases, stabilizing features therefore do not sufficiently support the fragile cutting surface. In other cases, the cutting elements may penetrate further into the formation than predicted by the stabilizing features, so that the cutting tips become overloaded despite the presence of the stabilizing features. Furthermore, the manufacturing process used to create these bits may not allow the accuracy required to consistently reproduce a desired minimum DOC. One or more stabilizing features may contact the formation while others have clearance. This imbalance can introduce additional instability. Therefore, an improved apparatus and method for stabilizing a drill bit are desirable.
Further, bit stability while drilling may be achieved using two methodologies. An active method may be a bit designed to have minimum imbalanced force or desired high imbalanced force in certain directions. A passive method may be a bit designed to use features to suppress the magnitude of instability. In real applications, due to formation inhomogeneity and drill string vibration, a stable bit is often subject to varying load and drills in unstable mode. Thus, passive stability may be desirable on a bit if stability is of interest. Features such as these may be sufficient in providing protection with some lateral vibrations, however, may not provide enough protection from significant whirl and/or torsional vibrations.
Accordingly, there exists a need for improvements in fixed cutter bits, including the passive stability of a bit by reducing the magnitude of instability when vibrations occur during drilling operations.